A fiber suspending agent for lost-circulation materials

ABSTRACT

A treatment fluid comprises: a base fluid; a lost-circulation material, wherein the lost-circulation material inhibits or prevents some or all of the treatment fluid from penetrating into a subterranean formation from a wellbore, wherein the wellbore penetrates the subterranean formation; and a suspending agent, wherein the suspending agent consists of a plurality of fibers, and wherein the suspending agent provides a lost-circulation material distribution of at least 30% for a test treatment fluid consisting essentially of the base fluid, the lost-circulation material, and the suspending agent at the temperature of a lost-circulation zone of the subterranean formation and static aging for at least 1 hour.

TECHNICAL FIELD

Suspending agents can be used to uniformly distribute insolubleparticles throughout a base fluid. The type of suspending agent and theproperties of the suspending agent can be used to determine thesuspendability of a suspending agent. The treatment fluid including thesuspending agent can be used in oil or gas operations.

DETAILED DESCRIPTION

As used herein, the words “comprise,” “have,” “include,” and allgrammatical variations thereof are each intended to have an open,non-limiting meaning that does not exclude additional elements or steps.As used herein, the words “consisting essentially of,” and allgrammatical variations thereof are intended to limit the scope of aclaim to the specified materials or steps and those that do notmaterially affect the basic and novel characteristic(s) of the claimedinvention. For example, a test treatment fluid can consist essentiallyof the base fluid, the lost-circulation material, and the suspendingagent. The test treatment fluid can contain other ingredients so long asthe presence of the other ingredients does not materially affect thebasic and novel characteristics of the claimed invention, i.e., so longas the test treatment fluid exhibits the desired lost-circulationmaterial distribution.

As used herein, a “fluid” is a substance having a continuous phase thattends to flow and to conform to the outline of its container when thesubstance is tested at a temperature of 71° F. (22° C.) and a pressureof one atmosphere “atm” (0.1 megapascals “MPa”). A fluid can be a liquidor gas. A homogeneous fluid has only one phase; whereas, a heterogeneousfluid has more than one distinct phase. A suspension is an example of aheterogeneous fluid. A heterogeneous fluid can be: a slurry, whichincludes a continuous liquid phase and undissolved solid particles asthe dispersed phase; an emulsion, which includes a continuous liquidphase and at least one dispersed phase of immiscible liquid droplets; afoam, which includes a continuous liquid phase and a gas as thedispersed phase; or a mist, which includes a continuous gas phase and aliquid as the dispersed phase. A heterogeneous fluid will have only onecontinuous phase, but can have more than one dispersed phase. It is tobe understood that any of the phases of a heterogeneous fluid (e.g., acontinuous or dispersed phase) can contain dissolved or undissolvedsubstances or compounds. As used herein, the phrase “aqueous-based”means a solution wherein an aqueous liquid is the solvent or a colloidwherein an aqueous liquid is the continuous phase. As used herein, thephrase “oil-based” means a solution wherein a hydrocarbon liquid is thesolvent or a colloid wherein a hydrocarbon liquid is the continuousphase.

Oil and gas hydrocarbons are naturally occurring in some subterraneanformations. In the oil and gas industry, a subterranean formationcontaining oil or gas is referred to as a reservoir. A reservoir may belocated under land or off shore. Reservoirs are typically located in therange of a few hundred feet (shallow reservoirs) to a few tens ofthousands of feet (ultra-deep reservoirs). In order to produce oil orgas, a wellbore is drilled into a reservoir or adjacent to a reservoir.The oil, gas, or water produced from the wellbore is called a reservoirfluid.

A well can include, without limitation, an oil, gas, or water productionwell, or an injection well. As used herein, a “well” includes at leastone wellbore. The wellbore is drilled into a subterranean formation. Thesubterranean formation can be a part of a reservoir or adjacent to areservoir. A wellbore can include vertical, inclined, and horizontalportions, and it can be straight, curved, or branched. As used herein,the term “wellbore” includes any cased, and any uncased, open-holeportion of the wellbore. A near-wellbore region is the subterraneanmaterial and rock of the subterranean formation surrounding thewellbore. As used herein, a “well” also includes the near-wellboreregion. The near-wellbore region is generally considered the regionwithin approximately 100 feet radially of the wellbore. As used herein,“into a well” means and includes into any portion of the well, includinginto the wellbore or into the near-wellbore region via the wellbore.

A portion of a wellbore may be an open hole or cased hole. In anopen-hole wellbore portion, a tubing string may be placed into thewellbore. The tubing string allows fluids to be introduced into orflowed from a remote portion of the wellbore. In a cased-hole wellboreportion, a casing is placed into the wellbore, which can also contain atubing string. A wellbore can contain an annulus. Examples of an annulusinclude, but are not limited to: the space between the wall of thewellbore and the outside of a tubing string in an open-hole wellbore;the space between the wall of the wellbore and the outside of a casingin a cased-hole wellbore; and the space between the inside of a casingand the outside of a tubing string in a cased-hole wellbore.

During drilling operations, a wellbore is formed using a drill bit. Adrill string can be used to aid the drill bit in drilling through asubterranean formation to form the wellbore. The drill string caninclude a drilling pipe. A treatment fluid adapted for this purpose isreferred to as a drilling fluid or drilling mud. The drilling fluid maybe circulated downwardly through the drilling pipe, and back up theannulus between the wellbore and the outside of the drilling pipe.During drilling or other operations such as completion, some of the baseliquid of the treatment fluid can undesirably flow into the subterraneanformation instead of remaining in the wellbore and being circulated backup to the wellhead. This is known as lost circulation. In order toovercome the problems associated with lost circulation, alost-circulation material (“LCM”) can be used. LCMs can be swellable ornon-swellable, granular-shaped substances. As the treatment fluid isplaced into the well, the LCM can eliminate or lessen the amount ofliquid base fluid entering the subterranean formation. For example, theparticles of the LCM can build upon each other and form a bridge overhighly-permeable areas of the formation, such as natural fissures,fractures, and vugs, or induced fractures. The bridge can eliminate orreduce the amount of liquid base fluid entering the formation via thewellbore.

There is a need for improved suspending agents that can be used tosuspend LCMs in a treatment fluid. It has been discovered that fiberscan be added to a treatment fluid as a suspending agent for LCMs. Thesuspendability of the fibers can be experimentally determined in alaboratory.

It is to be understood that if any laboratory test (e.g., LCMDistribution) requires the test be performed at a specified temperatureand possibly a specified pressure, then the temperature and pressure ofthe test composition is ramped up to the specified temperature andpressure after being mixed at ambient temperature and pressure. Forexample, the composition can be mixed at 71° F. (22° C.) and 1 atm (0.1MPa) and then placed into the testing apparatus and the temperature ofthe composition can be ramped up to the specified temperature. As usedherein, the rate of ramping up the temperature can be in the range ofabout 1° F./min to about 10° F./min to simulate actual wellboreconditions. After the composition is ramped up to the specifiedtemperature and possibly specified pressure, the composition ismaintained at that temperature and pressure for the duration of thetesting.

As used herein, the “LCM Distribution” test was performed as follows.The base fluid was hot rolled at the specified temperature for aspecified period of time under a specific pressure. The base fluid caninclude a multitude of ingredients and can be, for example, a drillingmud. The treatment fluid was then mixed by first adding the hot-rolledbase fluid to a mixing container. The lost-circulation material “LCM”and the suspending agent fibers were added to the base fluid. The fluidwas then mixed thoroughly using a spatula. The mixture was then heatedto the specified temperature at ambient pressure (˜1 atm). The mixturewas then poured into a glass vessel that was pre-heated to the specifiedtemperature. The glass vessel containing the mixture was then placedinto a pre-heated stainless steel aging cell. The mixture was thenstatic aged for 2 hours at the specified temperature. The glass vesselwas then placed into a water bath for about 10 minutes (min) to cooldown. The mixture in the glass vessel was then separated into two equalsections, the top half and the bottom half. The quantity of LCM in eachhalf was obtained by filtering each mixture half through anappropriately sized mesh depending on the particle size of the LCM addedto the base fluid. The LCM particulates and fibers were rinsed withwater or base oil to remove any adhered base fluid. The LCM and fibersfrom each half were dried in an oven at 221° F. (105° C.), then cooled,and then weighed. The following equation was used to determine the LCMDistribution.

${\% \mspace{14mu} L\; C\; M^{Top}} = {\frac{L\; C\; M^{Top}}{{L\; C\; M^{Top}} + {L\; C\; M^{Bottom}}}*100}$

where LCM^(Top) is the weight of LCM in the top half and LCM^(Bottom) isthe weight of the LCM in the bottom half. It should be noted that thefibers can be separated from the LCM and just the LCM can be weighed orboth the LCM plus the fibers can be weighed in which case the precedingequation would include the weight of the LCM plus the fibers in eachhalf. An LCM Distribution of 50% indicates that zero settling occurredbecause 50% of the LCM (and optionally the fibers too) still remains inthe top half of the fluid. By contrast, an LCM Distribution of 0%indicates that all of the LCM settled to the bottom half of the fluid.As used herein, an LCM Distribution between 40% to 50% is consideredexcellent suspendability, greater than or equal to 30% is considered astable fluid, 5% to 30% is considered weak suspendability, and <5% isconsidered no suspendability.

According to an embodiment, a treatment fluid comprises: a base fluid; alost-circulation material, wherein the lost-circulation materialinhibits or prevents some or all of the treatment fluid from penetratinginto a subterranean formation from a wellbore, wherein the wellborepenetrates the subterranean formation; and a suspending agent, whereinthe suspending agent consists of a plurality of fibers, and wherein thesuspending agent provides a lost-circulation material distribution of atleast 30% for a test treatment fluid consisting essentially of the basefluid, the lost-circulation material, and the suspending agent at thetemperature of a lost-circulation zone of the subterranean formation andstatic aging for at least 1 hour.

According to another embodiment, a method of treating a portion ofwellbore comprises: introducing the treatment fluid into the portion ofthe wellbore.

The discussion of preferred embodiments regarding the treatment fluid orany ingredient in the treatment fluid, is intended to apply to all ofthe composition embodiments and method embodiments. Any reference to theunit “gallons” means U.S. gallons.

It is to be understood that while the treatment fluid can contain otheringredients, it is the suspending agent that is primarily or whollyresponsible for providing the requisite LCM distribution and a stabletreatment fluid. For example, a test treatment fluid consistingessentially of, or consisting of, the base fluid, the LCM, and thesuspending agent and in the same proportions as the treatment fluid canhave a desirable LCM distribution. Therefore, it is not necessary forthe treatment fluid to include other additives, such as a viscosifyingagent or other suspending agents to provide for the desired LCMdistribution and stable fluid. It is also to be understood that anydiscussion related to a “test treatment fluid” is included for purposesof demonstrating that the treatment fluid can contain other ingredients,but it is the suspending agent that creates the desirable LCMdistribution and stable fluid. Therefore, while it may not be possibleto perform a test in a wellbore for the specific treatment fluid, onecan formulate a test treatment fluid to be tested in a laboratory toidentify if the ingredients and concentration of the ingredients willprovide the stated LCM distribution.

The treatment fluid includes a base fluid. The treatment fluid can be aheterogeneous fluid, for example, a slurry or an emulsion or invertemulsion. Any of the phases of the heterogeneous fluid can containdissolved substances and/or undissolved substances. The base fluid canbe the liquid continuous phase of the heterogeneous fluid. The basefluid can be an aqueous liquid, an aqueous miscible liquid, or ahydrocarbon liquid. Suitable aqueous-based fluids can include, but arenot limited to, fresh water; saltwater (e.g., water containing one ormore water-soluble salts dissolved therein); brine (e.g., saturated saltwater); seawater; and any combination thereof. Suitable aqueous-misciblefluids can include, but are not limited to, alcohols (e.g., methanol,ethanol, n-propanol, isopropanol, n-butanol, sec-butanol, isobutanol,and t-butanol); glycerins; glycols (e.g., polyglycols, propylene glycol,and ethylene glycol); polyglycol amines; polyols; any derivativethereof; any in combination with salts (e.g., sodium chloride, calciumchloride, magnesium chloride, potassium chloride, sodium bromide,calcium bromide, zinc bromide, potassium carbonate, sodium formate,potassium formate, cesium formate, sodium acetate, potassium acetate,calcium acetate, ammonium acetate, ammonium chloride, ammonium bromide,sodium nitrate, potassium nitrate, ammonium nitrate, ammonium sulfate,calcium nitrate, sodium carbonate, and potassium carbonate); any incombination with an aqueous-based fluid; and any combination thereof.

The hydrocarbon liquid can be synthetic. The hydrocarbon liquid can beselected from the group consisting of: a fractional distillate of crudeoil; a fatty derivative of an acid, an ester, an ether, an alcohol, anamine, an amide, or an imide; a saturated hydrocarbon; an unsaturatedhydrocarbon; a branched hydrocarbon; a cyclic hydrocarbon; and anycombination thereof. Crude oil can be separated into fractionaldistillates based on the boiling point of the fractions in the crudeoil. An example of a suitable fractional distillate of crude oil isdiesel oil. A commercially-available example of a fatty acid ester isPETROFREE® ESTER base fluid, marketed by Halliburton Energy Services,Inc. The saturated hydrocarbon can be an alkane or paraffin. Theparaffin can be an isoalkane (isoparaffin), a linear alkane (paraffin),or a cyclic alkane (cycloparaffin). An example of an alkane is BAROIDALKANE™ base fluid, marketed by Halliburton Energy Services, Inc.Examples of suitable paraffins include, but are not limited to: BIO-BASE360® (an isoalkane and n-alkane); BIO-BASE 300™ (a linear alkane);BIO-BASE 560® (a blend containing greater than 90% linear alkanes); andESCAID 110™ (a mineral oil blend of mainly alkanes and cyclic alkanes).The BIO-BASE liquids are available from Shrieve Chemical Products, Inc.in The Woodlands, Tex. The ESCAID liquid is available from ExxonMobil inHouston, Tex. The unsaturated hydrocarbon can be an alkene, alkyne, oraromatic. The alkene can be an isoalkene, linear alkene, or cyclicalkene. The linear alkene can be a linear alpha olefin or an internalolefin. An example of a linear alpha olefin is NOVATEC™, available fromM-I SWACO in Houston, Tex. Examples of internal olefins-based drillingfluids include, ENCORE® drilling fluid and ACCOLADE® internal olefin andester blend drilling fluid, marketed by Halliburton Energy Services,Inc. An example of a diesel oil-based drilling fluid is INVERMUL®,marketed by Halliburton Energy Services, Inc.

The treatment fluid includes a lost-circulation material (“LCM”),wherein the LCM inhibits or prevents some or all of the treatment fluidfrom penetrating into a subterranean formation, wherein the wellborepenetrates the subterranean formation. The LCM can be of any materialknown in the art suitable for use as an LCM in a wellbore operation.Depending on the size of the pores of the subterranean formation and thesize of the bridges formed by the LCM, the bridges can help inhibit orprevent fluid flow from the wellbore into the formation or also from theformation into the wellbore (depending on the specific oil or gasoperation being performed). It should be understood that while some ofthe treatment fluid may penetrate into the subterranean formation, themajority of the treatment fluid should remain in the wellbore. Moreover,as used herein, the term “penetrate” and all grammatical variationsthereof is not intended to preclude some penetration of a certain depth,for example, a few inches, into the formation, but rather is meant toinclude penetration of depths that would be considered in the industryas lost circulation, and could likely impair oil or gas operations orincrease the cost of performing the oil or gas operation. According toan embodiment, the LCM is in at least a sufficient concentration suchthat fluid is inhibited or prevented from flowing into the formationfrom the wellbore. The LCM can be in a concentration in the range ofabout 0.5 to about 200 pounds per barrel of the base fluid or about 0.5%to about 50% by volume of the base fluid.

Suitable LCMs include, but are not limited to: ground coal; petroleumcoke; sized calcium carbonate; asphaltene; perlite; cellophane;cellulose; ground tire material; ground oyster shell; vitrified shale; aplastic material; paper fiber; wood; cement; hardened foamed cement;glass; foamed glass; sand; bauxite; a ceramic material; a polymericmaterial (such as ethylene vinyl acetate); a polytetrafluoroethylenematerial; a nut shell; a seed shell piece; a fruit pit piece; clay;silica; alumina; fumed carbon; carbon black; graphite; mica; titaniumoxide; meta-silicate; calcium silicate; kaolin; talc; zirconia; boron;fly ash; a hollow glass microsphere; any composite particle thereof; andany combination thereof. Examples of suitable commercially-availableLCMs include, but are not limited to, WALL-NUT®, BARACARB®, STEELSEAL®,N-SQUEEZE™, N-SEAL™, N-PLEX™, HYDRO-PLUG®, DURO-SQUEEZE™ H, BAROFIBRE®,and BAROFIBRE® O, marketed by Halliburton Energy Services, Inc.

The particles of the LCM can be formed by the combination of one or moretypes of LCM materials using a consolidating agent. Suitableconsolidating agents may include, but are not limited to: non-aqueoustackifying agents; aqueous tackifying agents; emulsified tackifyingagents; silyl-modified polyamide compounds; resins; cross-linkableaqueous polymer compositions; polymerizable organic monomercompositions; consolidating agent emulsions; zeta-potential modifyingaggregating compositions; silicon-based resins; and binders.Combinations and/or derivatives of these may also be suitable. It iswithin the ability of one of ordinary skill in the art, with the benefitof this disclosure, to determine the type and amount of consolidatingagent to include to achieve the desired results.

The LCM particles can be of any size or shape combination compatiblewith the specifics of the wellbore and subterranean formation that ispenetrated by the wellbore. The LCMs can be substantially spherical orsubstantially non-spherical in shape, and can also be hollow. The LCMparticles can be, for example, spherical-shaped; cubic-shaped;rod-shaped; cone-shaped; ellipse-shaped; cylinder-shaped;polygon-shaped; pyramid-shaped; torus-shaped; cross-shaped;lattice-shaped; star-shaped; or any other shape. The LCM particles canbe of any size required for use in the particular subterraneanformation. According to an embodiment, the LCM can have a particle sizedistribution such that at least 80% of the LCM particles have a size inthe range from about 2 to about 400 mesh, U.S. Sieve Series, preferablyabout 8 to about 400 mesh, more preferably about 8 to about 120 mesh.The LCM particles can range in sphericity from about 0 to about 1,preferably about 0.1 to about 1. LCM particles that are substantiallynon-spherical (e.g., particles having sphericity values at leastbelow 1) can have a length to diameter aspect ratio in the range ofabout 1:1 to about 10:1.

The treatment fluid also includes a suspending agent. The suspendingagent consists of a plurality of fibers. The fibers can be in dry formor in a liquid suspension. The fibers can be natural, synthetic,biodegradable, and/or biocompatible. Examples of synthetic fibersinclude, but are not limited to, polymers or copolymers composed ofpolypropylene, polyaramid, polyester, polyacrylonitrile, and polyvinylalcohol. Examples of biodegradable fibers include, but are not limitedto, fibers composed of modified cellulose, chitosan, soya, modifiedchitosan, polycaprolactone, polylactic acid, poly(3-hydroxybutyrate),polyhydroxy-alkanoates, polyglycolic acid “PGA”, polylactic acid “PLA”,polyorthoesters, polycarbonates, polyaspartic acid, polyphosphoesters,soya, or copolymers thereof. Examples of other suitable fibers include,fibers of cellulose including viscose cellulosic fibers, oil coatedcellulosic fibers, and fibers derived from a plant product like paperfibers; carbon including carbon fibers; melt-processed inorganic fibersincluding basalt fibers, wollastonite fibers, non-amorphous metallicfibers, ceramic fibers, and glass fibers. The fibers can also be acomposite fiber made from any combination of the preceding materials.There can also be a mixture of fibers wherein the fibers are composed ofdifferent substances. A commercially-available example of suitablefibers is BAROLIFT®, sweeping agent, marketed by Halliburton EnergyServices, Inc., which is a synthetic fiber. The fibers can have a fiberlength, diameter and have a concentration. The fibers can have a lengthto diameter aspect ratio in the range of about 2:1 to about 5,000:1.

The suspending agent provides a lost-circulation material distributionof at least 30% for a test treatment fluid consisting essentially of thebase fluid, the LCM, and the suspending agent at the temperature of alost-circulation zone of the subterranean formation and static aging forat least 1 hour. As used herein, the term “lost-circulation zone” meansthe location in the wellbore where lost-circulation is occurring andneeds to be treated with the treatment fluid. There can be more than onelost-circulation zone within the wellbore. More preferably, thesuspending agent provides an LCM distribution of at least 40%, morepreferably 50% at the stated testing conditions, wherein an LCMdistribution of 50% indicates zero settling of the LCM particles in thebase fluid.

The suspending agent can be in a concentration in the range of about 0.1pounds per barrel (ppb) to about 25 ppb of the base fluid. According toanother embodiment, the suspending agent is in at least a sufficientconcentration such that the suspending agent provides a lost-circulationmaterial distribution of at least 30%, preferably at least 40%, morepreferably 50%, for a test treatment fluid consisting essentially of thebase fluid, the LCM, and the suspending agent at the temperature of alost-circulation zone of the subterranean formation and static aging forat least 1 hour.

The fibers can have a fiber length. The fibers can have a distributionsuch that at least 90% of the fibers have a length in the range of about0.5 millimeters (mm) to about 25 mm. According to another embodiment,the fibers have a length such that the suspending agent provides alost-circulation material distribution of at least 30%, preferably atleast 40%, more preferably 50%, for a test treatment fluid consistingessentially of the base fluid, the LCM, and the suspending agent at thetemperature of a lost-circulation zone of the subterranean formation andstatic aging for at least 1 hour.

The fiber length and concentration may be inversely proportional. Forexample, for a given concentration of fibers, the desired LCMdistribution may be achieved by increasing the fiber length. Bycontrast, for a given fiber length, the desired LCM distribution may beachieved by increasing the concentration of the fibers.

The treatment fluid can be any fluid used in an oil or gas operationwhere prevention of lost circulation is desirable. For example, thetreatment fluid can be, without limitation, a drilling fluid, spacerfluid, completion fluid, fracturing fluid, or acidizing fluid.

The treatment fluid can also contain other ingredients, such as aviscosifier; a filtration control agent; a shale stabilizer; a weightingagent; a pH buffer; an emulsifier; an emulsifier activator (e.g., lime);a dispersion aid; a corrosion inhibitor; an emulsion thinner; anemulsion thickener; a gelling agent; a surfactant; a foaming agent; agas; a breaker; a biocide; a chelating agent; a scale inhibitor; a gashydrate inhibitor, a mutual solvent; an oxidizer; a reducer; a frictionreducer; a clay stabilizing agent; an oxygen scavenger; and anycombination thereof.

The viscosifiers can comprise any substance (e.g., a polymeric material)capable of increasing the viscosity of the treatment fluid. In certainembodiments, the viscosifier can comprise one or more polymers that haveat least two molecules that are capable of forming a crosslink in across-linking reaction in the presence of a crosslinking agent, and/orpolymers that have at least two molecules that are so cross-linked(i.e., a cross-linked viscosifier). The viscosifiers can benaturally-occurring; synthetic; or a combination thereof. Theviscosifiers of the present invention may also be cationic; anionic; ora combination thereof. Suitable viscosifiers for use in the treatmentfluids of the present invention include, but are not limited to,polysaccharides; biopolymers; and/or derivatives thereof that containone or more of these monosaccharide units: galactose; mannose;glucoside; glucose; xylose; arabinose; fructose; glucuronic acid; orpyranosyl sulfate. Examples of suitable polysaccharides include, but arenot limited to, guar gums (e.g., hydroxyethyl guar, hydroxypropyl guar,carboxymethyl guar, carboxymethylhydroxyethyl guar, andcarboxymethylhydroxypropyl guar (“CMHPG”)); cellulose derivatives (e.g.,hydroxyethyl cellulose, carboxyethylcellulose, carboxymethylcellulose,and carboxymethylhydroxyethylcellulose); xanthan; scleroglucan;succinoglycan; diutan; and combinations thereof.

Suitable synthetic polymers for use as a viscosifier in the treatmentfluids include, but are not limited to, 2,2′-azobis(2,4-dimethylvaleronitrile); 2,2′-azobis(2,4-dimethyl-4-methoxy valeronitrile);polymers and copolymers of acrylamide ethyltrimethyl ammonium chloride;acrylamide; acrylamido- and methacrylamido-alkyl trialkyl ammoniumsalts; acrylamidomethylpropane sulfonic acid; acrylamidopropyl trimethylammonium chloride; acrylic acid; dimethylaminoethyl methacrylamide;dimethylaminoethyl methacrylate; dimethylaminopropyl methacrylamide;dimethylaminopropylmethacrylamide; dimethyldiallylammonium chloride;dimethylethyl acrylate; fumaramide; methacrylamide; methacrylamidopropyltrimethyl ammonium chloride;methacrylamidopropyldimethyl-n-dodecylammonium chloride;methacrylamidopropyldimethyl-n-octylammonium chloride;methacrylamidopropyltrimethylammonium chloride; methacryloylalkyltrialkyl ammonium salts; methacryloylethyl trimethyl ammonium chloride;methacrylylamidopropyldimethylcetylammonium chloride;N-(3-sulfopropyl)-N-methacrylamidopropyl-N,N-dimethyl ammonium betaine;N,N-dimethylacrylamide; N-methylacrylamide;nonylphenoxypoly(ethyleneoxy)ethylmethacrylate; partially hydrolyzedpolyacrylamide; poly 2-amino-2-methyl propane sulfonic acid; polyvinylalcohol; sodium 2-acrylamido-2-methylpropane sulfonate; quaternizeddimethylaminoethylacrylate; quaternized dimethylaminoethylmethacrylate;any derivative thereof; and any combination thereof. In certainembodiments, the viscosifier can comprise anacrylamide/2-(methacryloyloxy)ethyltrimethylammonium methyl sulfatecopolymer. In certain embodiments, the viscosifier can comprise anacrylamide/2-(methacryloyloxy)ethyltrimethylammonium chloride copolymer.In certain embodiments, the viscosifier can comprise a derivatizedcellulose that comprises cellulose grafted with an allyl or a vinylmonomer. Additionally, polymers and copolymers that comprise one or morefunctional groups, such as, for example, hydroxyl; cis-hydroxyl;carboxylic acids; derivatives of carboxylic acids; sulfate; sulfonate;phosphate; phosphonate; amino; or amide groups may be used asviscosifiers. An example of a commercially-available viscosifier isBARAZAN® D PLUS, marketed by Halliburton Energy Services, Inc.

The viscosifier can be present in the treatment fluids in aconcentration sufficient to provide the desired viscosity. In certainembodiments, the viscosifier(s) can be present in a concentration in therange of from about 0.1 to about 40 ppb of the base fluid, preferablyabout 0.1 to about 15 ppb of the base fluid.

The treatment fluid can also include one or more cross-linking agents.Examples of suitable crosslinking agents include, but are not limitedto, metal ions; borate ions; magnesium ions; zirconium IV ions; titaniumIV ions; aluminum ions; antimony ions; chromium ions; iron ions; copperions; magnesium ions; zinc ions; and any combination thereof. These ionsmay be provided by providing any compound that is capable of producingone or more of these ions, such as, for example, ferric chloride; boricacid; disodium octaborate tetrahydrate; sodium diborate; pentaborates;ulexite; colemanite; magnesium oxide; zirconium lactate; zirconiumtriethanol amine; zirconium lactate triethanolamine; zirconiumcarbonate; zirconium acetylacetonate; zirconium malate; zirconiumcitrate; zirconium diisopropylamine lactate; zirconium glycolate;zirconium triethanol amine glycolate; zirconium lactate glycolate;titanium lactate; titanium malate; titanium citrate; titanium ammoniumlactate; titanium triethanolamine; titanium acetylacetonate; aluminumlactate; aluminum citrate; antimony compounds; chromium compounds; ironcompounds; copper compounds; zinc compounds; and any combinationthereof. The choice of a particular cross-linking agent will be governedby several considerations that will be recognized by one skilled in theart including, but not limited to, the type of viscosifier(s) included,the molecular weight of the viscosifier(s), the conditions in thesubterranean formation, the safety handling requirements, the pH of thetreatment fluid, and so on.

When included, suitable cross-linking agents can be in a concentrationsufficient to provide the desired degree of cross-linking betweenmolecules of the viscosifier. In certain embodiments, the cross-linkingagent is in a concentration in the range from about 0.01 to about 10 ppbof the base fluid, preferably about 0.5 to about 5 ppb of the basefluid.

Suitable filtration control agents can comprise any substance capable ofmanaging filtration, including bridging, bonding, deflocculation, andviscosity. The filtration control agents can also function to reducefilter cake permeability. Suitable filtration control agents include,but are not limited to, polyanionic cellulose; polyacrylate; modifiedlignite; powdered resin; modified starch; carboxymethylcellulose; andany combination thereof. Suitable commercially-available filtrationcontrol agents include PAC™-R and DEXTRID®, marketed by HalliburtonEnergy Services, Inc. The filtration control agent can be in aconcentration in the range of about 0.1 to about 20 ppb of the treatmentfluid, preferably about 0.1 to about 5 ppb of the treatment fluid.

Suitable shale stabilizers can include, but are not limited to, longchain alcohols; polyols; polyglycols; amine inhibitor; sodium orpotassium silicate; partially hydrolyzed polyacrylamides; polyalkeneglycols; anionic surfactants; salt solutions containing, for example,sodium chloride, potassium chloride, or ammonium chloride; cationicpolymers and oligomers, for example, poly(dimethyldiallylammoniumchloride), cationic poly(acrylamide) and cationicpoly(dimethylaminoethylmethacrylate); and any combination thereof.Examples of commercially-available shale stabilizers include CLAY SYNC™,CLAYSEAL® PLUS, PERFORMATROL®, GEM™ GP, GEM™ CP, BORE-HIB®, BARO-TROL®PLUS, EZ-MUD®, EZ-MUD® GOLD, and BARASIL™-S, marketed by HalliburtonEnergy Services, Inc. The shale stabilizer can be in a concentration inthe range of about 0.1 to about 30 ppb of the treatment fluid,preferably about 1 to about 15 ppb of the treatment fluid.

The weighting agent can be any material capable of increasing thedensity of the treatment fluid. The weighting agent can additionally aidin controlling formation pressures and stabilizing the wellbore.Suitable weighting agents include, but are not limited to, barite;hematite; ilmentite; manganese tetraoxide; galena; calcium carbonate;iron oxide; manganese oxide; magnetite; siderite; celesite; dolomite;manganese carbonate and any combination thereof. Examples of acommercially-available weighting agents include, but are not limited to,BAROID®, BARODENSE®, MICROMAX™, and combinations thereof, marketed byHalliburton Energy Services, Inc. The weighting agent can be in aconcentration in the range of about 1 to about 1,500 ppb (about 4 toabout 5,800 kilograms per cubic meter “kg/m³”) of the treatment fluid,preferably about 10 to about 700 ppb of the treatment fluid. Accordingto another embodiment, the weighting agent is in at least a sufficientconcentration such that the drilling fluid has a density in the range ofabout 9 to about 20 pounds per gallon (ppg) (about 1.078 to about 2.397kilograms per liter “kg/L”). Preferably, the weighting agent is in atleast a sufficient concentration such that the drilling fluid has adensity in the range of about 9 to about 18 ppg (about 1.1 to about 2.4kg/L).

Suitable pH buffers can be any pH buffer capable of controlling the pHof the treatment fluid (e.g., increasing or decreasing the pH). The pHbuffers can be included in the treatment fluid to enhance the stabilityof the treatment fluid, for example. Suitable pH buffers can include,but are not limited to: sodium carbonate; potassium carbonate; sodiumbicarbonate; potassium bicarbonate; sodium diacetate; potassiumdiacetate; ammonium diacetate; sodium phosphate; potassium phosphate;sodium hydrogen phosphate; potassium hydrogen phosphate; sodiumdihydrogen phosphate; potassium dihydrogen phosphate; sodium borate;magnesium oxide; sulfamic acid; sodium hydroxide; potassium hydroxide;citric acid; tartaric acid; and any combination thereof. The pH buffercan be in at least a sufficient concentration to maintain the pH of thetreatment fluid at a desired level. According to another embodiment, thepH buffer is in a concentration in the range of about 0.01 to about 10ppb (about 0.04 to about 39 kg/m³) of the treatment fluid, preferablyabout 0.1 to about 2 ppb (about 0.4 to about 8 kg/m³) of the treatmentfluid.

The treatment fluid can also include a friction reducer.Commercially-available examples of a suitable friction reducers include,but are not limited to, BARO-LUBE GOLD SEAL™, TORQ-TRIM® II, graphiticcarbon, and combinations thereof, marketed by Halliburton EnergyServices, Inc. The friction reducer can be in a concentration of atleast 0.5 ppb (2 kg/m³) of the drilling fluid. In an embodiment, thefriction reducer is in a concentration in the range of about 0.5 toabout 5 ppb (about 2 to about 19 kg/m³) of the drilling fluid.

According to an embodiment, the methods include the step of introducingthe treatment fluid into a portion of the wellbore. The well can be anoil, gas, or water production well, a geothermal well, or an injectionwell. The well includes the wellbore. The wellbore penetrates thesubterranean formation. The subterranean formation can be part of areservoir or adjacent to a reservoir. The step of introducing thetreatment fluid can be a drilling fluid for the purpose of drilling thewellbore. The drilling fluid can be in a pumpable state before andduring introduction into the subterranean formation. The well caninclude an annulus. The step of introducing the treatment fluid caninclude introducing the treatment fluid into a portion of the annulus.

The methods can further include introducing a spacer fluid into thewellbore after the step of introducing the treatment fluid. The methodscan also further include introducing a cement composition into thewellbore after the step of introducing the treatment fluid and/or thespacer fluid. As used herein, a “cement composition” is a mixture of atleast cement and water, and possibly additives. As used herein, the term“cement” means an initially dry substance that, in the presence ofwater, acts as a binder to bind other materials together. An example ofcement is Portland cement. The step of introducing the cementcomposition can be for the purpose of at least one of the following:well completion; foam cementing; primary or secondary cementingoperations; well-plugging; and gravel packing. The cement compositioncan be in a pumpable state before and during introduction into thewellbore. The step of introducing can include introducing the cementcomposition into a portion of an annulus. Of course there can also bemore than one treatment fluid introduced into a portion of the wellbore.The treatment fluids can be the same or different, for example, onetreatment fluid can be a drilling fluid and another treatment fluid canbe a spacer fluid, so long as each treatment fluid contains at least thebase fluid, the LCMs, and the suspending agent.

The method embodiments can also include allowing the cement compositionto set. The step of allowing can be performed after the step ofintroducing the cement composition into the wellbore. The method canfurther include perforating, fracturing, and/or performing an acidizingtreatment after the step of allowing.

EXAMPLES

To facilitate a better understanding of the preferred embodiments, thefollowing examples of certain aspects of the preferred embodiments aregiven. The following examples are not the only examples that could begiven according to the preferred embodiments and are not intended tolimit the scope of the invention.

Unless stated otherwise, the treatment fluids were tested according tothe procedure for the specific test as described in The DetailedDescription section above. Treatment fluid A had a density of 17 poundsper gallon (2.0 kilograms per liter) and included a NaCl brine as thebase fluid; BARAZAN® D PLUS visosifier at a concentration of 0.65 poundsper barrel of the treatment fluid (ppb); PAC™-R fluid loss additive at aconcentration of 1 ppb; DEXTRID® filtration control agent at aconcentration of 2 ppb; BAROID® weighting agent in a concentrationsufficient to produce the 17 ppg density treatment fluid; and BARABUF®pH buffer in a concentration of 0.15 ppb.

Table 1 provides rheology, low-shear yield point “LSYP”, and 10 secondand 10 minute yield strength data for Treatment fluid A using a FANN 35rheometer.

TABLE 1 10 S/10 min LSYP gel strength (lb/100 (lb/100 Rheology sq. ft.)sq. ft.) rpm 600 300 200 100 6 3 5 7/9 Dial 127 84 67 46 9 7 Reading(lb/100 sq. ft.)

Table 2 contains fiber length in millimeters “mm,” fiber concentrationin pounds per barrel of Treatment fluid A “ppb,” and LCM distributiondata for the Treatment fluid A further containing an insolubleparticulate of BARACARB® lost-circulation material “LCM” at aconcentration of between 4-5% by volume of Treatment fluid A and varyingconcentrations and fiber lengths of BAROLIFT® synthetic fiber as thesuspending agent. BARACARB® lost-circulation material was ground marblehaving a particle size in the range of 1,400 to 1,680 micrometers and adensity of 2.7 grams per cubic centimeter. The LCM distribution test wasperformed after hot rolling for 16 hours and static aging for 2 hours ata temperature of 150° F. (66° C.).

TABLE 2 Fiber Length Fiber Concentration LCM (mm) (ppb) Distribution 3 320.0% 3 6 48.0% 4 0.5 7.2% 6 1 7.9% 6 2 47.0% 8 0.5 18.7% 12 0.5 43.0%

As can be seen in Table 2, fiber length and fiber concentration areinversely proportional. For example, for a given concentration, 0.5 ppb,the longer the fiber length, the better suspendability of the fibers.Also, for a given fiber length, 3 mm or 6 mm, an increase inconcentration can yield a fluid with a desired LCM Distribution.

The exemplary fluids and additives disclosed herein may directly orindirectly affect one or more components or pieces of equipmentassociated with the preparation, delivery, recapture, recycling, reuse,and/or disposal of the disclosed fluids and additives. For example, thedisclosed fluids and additives may directly or indirectly affect one ormore mixers, related mixing equipment, mud pits, storage facilities orunits, fluid separators, heat exchangers, sensors, gauges, pumps,compressors, and the like used to generate, store, monitor, regulate,and/or recondition the exemplary fluids and additives. The disclosedfluids and additives may also directly or indirectly affect anytransport or delivery equipment used to convey the fluids and additivesto a well site or downhole such as, for example, any transport vessels,conduits, pipelines, trucks, tubulars, and/or pipes used to fluidicallymove the fluids and additives from one location to another, any pumps,compressors, or motors (e.g., topside or downhole) used to drive thefluids and additives into motion, any valves or related joints used toregulate the pressure or flow rate of the fluids, and any sensors (i.e.,pressure and temperature), gauges, and/or combinations thereof, and thelike. The disclosed fluids and additives may also directly or indirectlyaffect the various downhole equipment and tools that may come intocontact with the fluids and additives such as, but not limited to, drillstring, coiled tubing, drill pipe, drill collars, mud motors, downholemotors and/or pumps, floats, MWD/LWD tools and related telemetryequipment, drill bits (including roller cone, PDC, natural diamond, holeopeners, reamers, and coring bits), sensors or distributed sensors,downhole heat exchangers, valves and corresponding actuation devices,tool seals, packers and other wellbore isolation devices or components,and the like.

Therefore, the present invention is well adapted to attain the ends andadvantages mentioned as well as those that are inherent therein. Theparticular embodiments disclosed above are illustrative only, as thepresent invention may be modified and practiced in different butequivalent manners apparent to those skilled in the art having thebenefit of the teachings herein. Furthermore, no limitations areintended to the details of construction or design herein shown, otherthan as described in the claims below. It is, therefore, evident thatthe particular illustrative embodiments disclosed above may be alteredor modified and all such variations are considered within the scope andspirit of the present invention. While compositions and methods aredescribed in terms of “comprising,” “containing,” or “including” variouscomponents or steps, the compositions and methods also can “consistessentially of” or “consist of” the various components and steps.Whenever a numerical range with a lower limit and an upper limit isdisclosed, any number and any included range falling within the range isspecifically disclosed. In particular, every range of values (of theform, “from about a to about b,” or, equivalently, “from approximately ato b”) disclosed herein is to be understood to set forth every numberand range encompassed within the broader range of values. Also, theterms in the claims have their plain, ordinary meaning unless otherwiseexplicitly and clearly defined by the patentee. Moreover, the indefinitearticles “a” or “an”, as used in the claims, are defined herein to meanone or more than one of the element that it introduces. If there is anyconflict in the usages of a word or term in this specification and oneor more patent(s) or other documents that may be incorporated herein byreference, the definitions that are consistent with this specificationshould be adopted.

What is claimed is:
 1. A treatment fluid comprising: a base fluid; alost-circulation material, wherein the lost-circulation materialinhibits or prevents some or all of the treatment fluid from penetratinginto a subterranean formation from a wellbore, wherein the wellborepenetrates the subterranean formation; and a suspending agent, whereinthe suspending agent consists of a plurality of fibers, and wherein thesuspending agent provides a lost-circulation material distribution of atleast 30% for a test treatment fluid consisting essentially of the basefluid, the lost-circulation material, and the suspending agent at thetemperature of a lost-circulation zone of the subterranean formation andstatic aging for at least 1 hour.
 2. The treatment fluid according toclaim 1, wherein the base fluid comprises an aqueous liquid, an aqueousmiscible liquid, or a hydrocarbon liquid.
 3. The treatment fluidaccording to claim 1, wherein the lost-circulation material is in atleast a sufficient concentration such that fluid is inhibited orprevented from flowing into the subterranean formation from thewellbore.
 4. The treatment fluid according to claim 1, wherein thelost-circulation material is in a concentration in the range of about0.5 to about 200 pounds per barrel of the base fluid.
 5. The treatmentfluid according to claim 1, wherein the lost-circulation material isselected from the group consisting of: ground coal; petroleum coke;sized calcium carbonate; asphaltene; perlite; cellophane; cellulose;ground tire material; ground oyster shell; vitrified shale; a plasticmaterial; paper fiber; wood; cement; hardened foamed cement; glass;foamed glass; sand; bauxite; a ceramic material; a polymeric material(such as ethylene vinyl acetate); a polytetrafluoroethylene material; anut shell; a seed shell piece; a fruit pit piece; clay; silica; alumina;fumed carbon; carbon black; graphite; mica; titanium oxide;meta-silicate; calcium silicate; kaolin; talc; zirconia; boron; fly ash;a hollow glass microsphere; any composite particle thereof; and anycombination thereof
 6. The treatment fluid according to claim 1, whereinthe lost-circulation material has a particle size distribution such thatat least 80% of the lost-circulation material particles have a size inthe range from about 2 to about 400 mesh.
 7. The treatment fluidaccording to claim 1, wherein the fibers are in dry form or in a liquidsuspension.
 8. The treatment fluid according to claim 1, wherein thefibers are natural, synthetic, biodegradable, biocompatible, orcombinations thereof.
 9. The treatment fluid according to claim 1,wherein the fibers are composed of polypropylene, polyaramid, polyester,polyacrylonitrile, polyvinyl alcohol, modified cellulose, chitosan,modified chitosan, polycaprolactone, polylactic acid,poly(3-hydroxybutyrate), polyhydroxy-alkanoates, polyglycolic acid,polylactic acid, polyorthoesters, polycarbonates, polyaspartic acid,polyphosphoesters, soya, copolymers thereof, and combinations thereof.10. The treatment fluid according to claim 1, wherein the suspendingagent provides a lost-circulation material distribution of at least 40%for the test treatment fluid at the temperature of a lost-circulationzone of the subterranean formation and static aging for at least 1 hour.11. The treatment fluid according to claim 1, wherein the suspendingagent is in a concentration in the range of about 0.1 ppb to about 25ppb of the base fluid.
 12. The treatment fluid according to claim 1,wherein the suspending agent is in at least a sufficient concentrationsuch that the suspending agent provides a lost-circulation materialdistribution of at least 30% for the test treatment fluid at thetemperature of a lost-circulation zone of the subterranean formation andstatic aging for at least 1 hour.
 13. The treatment fluid according toclaim 1, wherein the fibers have a distribution such that at least 90%of the fibers have a length in the range of about 0.5 to about 25millimeters.
 14. The treatment fluid according to claim 1, wherein thefibers have a length such that the suspending agent provides alost-circulation material distribution of at least 30% for the testtreatment fluid at the temperature of a lost-circulation zone of thesubterranean formation and static aging for at least 1 hour.
 15. Thetreatment fluid according to claim 1, wherein the treatment fluidfurther comprises one or more additional ingredients.
 16. The treatmentfluid according to claim 15, wherein the additional ingredients areselected from the group consisting of a viscosifier; a filtrationcontrol agent; a shale stabilizer; a weighting agent; a pH buffer; anemulsifier; an emulsifier activator; a dispersion aid; a corrosioninhibitor; an emulsion thinner; an emulsion thickener; a gelling agent;a surfactant; a foaming agent; a gas; a breaker; a biocide; a chelatingagent; a scale inhibitor; a gas hydrate inhibitor, a mutual solvent; anoxidizer; a reducer; a friction reducer; a clay stabilizing agent; anoxygen scavenger; and any combination thereof.
 17. The treatment fluidaccording to claim 16, wherein the treatment fluid is a drilling fluid.18. The treatment fluid according to claim 17, wherein the weightingagent is in at least a sufficient concentration such that the drillingfluid has a density in the range of about 9 to about 20 pounds pergallon.
 19. A method of treating a portion of wellbore comprising:introducing a treatment fluid into the portion of the wellbore, whereinthe treatment fluid comprises: a base fluid; a lost-circulationmaterial, wherein the lost-circulation material inhibits or preventssome or all of the treatment fluid from penetrating into a subterraneanformation from the wellbore, wherein the wellbore penetrates thesubterranean formation; and a suspending agent, wherein the suspendingagent consists of a plurality of fibers, and wherein the suspendingagent provides a lost-circulation material distribution of at least 30%for a test treatment fluid consisting essentially of the base fluid, thelost-circulation material, and the suspending agent at a temperature of150° F. after hot rolling for 16 hours and static aging for 2 hours. 20.The method according to claim 19, wherein the wellbore is part of awell, and wherein the well is an oil, gas, or water production well, ageothermal well, or an injection well.
 21. A system of treating asubterranean formation comprising: a pump; and a treatment fluid,wherein the treatment fluid comprises: a base fluid; a lost-circulationmaterial, wherein the lost-circulation material inhibits or preventssome or all of the treatment fluid from penetrating into thesubterranean formation from a wellbore, wherein the wellbore penetratesthe subterranean formation; and a suspending agent, wherein thesuspending agent consists of a plurality of fibers, wherein the pumppumps the treatment fluid into the subterranean formation.